It is a common practice to treat subterranean formations to increase the gross permeability or conductivity of such formations by procedures which are identified generally as fracturing processes. For example, it is a conventional practice to hydraulically fracture a well in order to produce one or more cracks or "fractures" in the surrounding formation by a mechanical breakdown of the formation. Fracturing may be carried out in wells which are completed in subterranean formations for virtually any purpose. The usual candidates for fracturing, or other stimulation procedures, are production wells completed in oil and/or gas containing formations. However, injection wells used in secondary or tertiary recovery operations, for example, for the injection of water or gas, may also be fractured in order to facilitate the injection of fluids in such subterranean formations.
Hydraulic fracturing is accomplished by injecting a hydraulic fracturing fluid into the well and imposing sufficient pressure on the fracturing fluid to cause the formation to breakdown with the attendant production of one or more fractures. The fracture or fractures formed may be horizontal or vertical with the latter usually predominating and with the tendency toward vertical fracture orientation increasing with the depth of the formation being fractured. Simultaneously with or subsequent to the formation of the fracture, a thickened carrier fluid having a propping agent such as sand or other particulate material suspended therein is introduced into the fracture. The propping agent is deposited in the fracture and functions to hold the fracture open after the pressure is released and the fracturing fluid withdrawn back into the well. The fracturing fluid usually contains a thickening agent in order to impart a sufficiently high viscosity to retain the propping agent in suspension or at least to reduce the tendency of the propping agent to settle out of the fluid.
Another common procedure for increasing the gross or apparent permeability of subterranean formations is acidizing. In this procedure, an aqueous solution of a suitable acid is injected into the well undergoing treatment under sufficient pressure to force it into the surrounding formation where it dissolves acid-soluble material in the formation to form small fissures or fractures. Carbonate-containing formations usually are treated with acidizing procedures and suitable acids for use in this regard are hydrochloric, formic and acetic acids. In some cases, however, sandstones containing little or no carbonate materials may be treated with acids such as hydrochloric or hydrofluoric acid or blends thereof.
Acidizing and hydraulic fracturing may also be employed in a common procedure. An acidizing fluid may be injected into the well under sufficient pressure to cause the formation to break down to produce fractures by hydraulic fracturing. This may be followed by a conventional nonacidic hydraulic fracturing fluid containing a propping agent or the acidizing fluid may itself contain a propping agent.
A number of additives may be employed in the course of a typical fracturing process. Thickening agents and propping agents are discussed above. In many cases, the initial portion of the fracturing fluid, referred to sometimes as a "pad" or "spearhead" will be free of propping agent and will be of a relatively low viscosity. Propping agent and thickening agent may be added to the portion of the fracturing fluid following the "spearhead". It is also conventional to employ a fluid loss additive in all or part of the fracturing fluid. In the case of hydraulic fracturing, the fluid loss agent minimizes the loss of fracturing fluid to the formation as the formation breakdown pressure is reached, thus aiding in the initiation of the fracture. In addition, once the fracture is formed, fracture propagation is enhanced by decreasing filtrate loss through the walls of the fracture into the formation matrix. It is also known in the art to incorporate a surfactant into at least a portion of the fracturing fluid to facilitate clean-up of the fracturing fluid at the conclusion of the stimulation operation. The surfactant functions to reduce the water-rock and oil-water interfacial tensions so that when the well is placed on production, the oil effectively displaces the water-based treating fluid from the formation matrix back into the well.
Other materials which may be incorporated with the more conventional fracturing liquids include normally gaseous materials which function to form a gas phase at the wellhead, or at the formation being fractured or both. One such process disclosed in U.S. Pat. No. 3,310,112 to Nielsen et al. involves the use of substantial quantities of liquid carbon dioxide in conjunction with a carrier liquid such as gelled water containing particulate propping agent. Very large quantities of carbon dioxide are employed in the Nielsen procedure to provide a ratio of at least 5 and preferably at least 7 volume units of carbon dioxide per volume of slurry of propping agent. The liquid carbon dioxide is converted in the formation to gas, due to pressure reduction when the wellhead pressure is released and the fact that the formation usually will be above the critical temperature of carbon dioxide. Upon releasing the pressure, a substantial portion of the gelled liquid is carried back out of the well by the gaseous carbon dioxide.
U.S. Pat. No. 3,937,283 to Blauer discloses a hydraulic fracturing process employing a foam formed of a gas such as nitrogen, carbon dioxide, air or hydrocarbon gases and a liquid such as water or an oil base liquid. The foam is characterized as having a Mitchell quality within the range of 0.5236-0.9999 and preferably between the range of 0.60-0.85.
U.S. Pat. No. 4,480,696 (Re 32,302) to Almond et al. discloses a water-carbon dioxide fracturing fluid characterized as an emulsion of liquified carbon dioxide and water at surface conditions which is converted into a gas and liquid foam upon heating in the formation to a temperature above the critical temperature of the carbon dioxide. The fracturing fluid contains a surfactant to stabilize the emulsion and the resulting foam and also gelling agents as well as propping agents. The volumetric ratio of liquid carbon dioxide to aqueous fluid is described as being in the range of 1:1 to about 20:1, preferably about 2:1 to 18:1, and the foam having a Mitchell quality of about 50% to an excess of about 96%.
A gelling agent such as a natural or synthetic hydratable polymer may be mixed with the aqueous liquid prior to formation of the emulsion. An inhibitor which functions to retard the hydration rate and therefore delay a viscosity increase in the solution may be employed. Compounds containing multivalent metals which release metal ions in aqueous solution to function as cross-linking or complexing agents for the hydratable polymer may be employed as inhibitors. A propping agent is added to the gelled aqueous liquid followed by admixing with the liquid carbon dioxide. As the fracturing fluid is introduced into the subterranean formation, the fluid is heated to above the critical temperature of carbon dioxide to produce a foam which maintains the viscosity of the fracturing fluid. After fracturing of the formation, the well is shut in for a stabilization period and then opened under controlled conditions to provide a pressure drop which causes the foam to break. The carbon dioxide gas functions to produce liquids from the fracturing area to leave the formation clean and ready for the commencement of production.